GMX Resources Inc., Oklahoma City, Okla., (NYSE: GMXR) has reported on the financial and operating results for the third quarter ended September 30, 2011.

2012 Capital Expenditure Plan

The 2012 capital expenditure plan of $131 million (excluding capitalized interest expense) pending closing of liquidity transaction(s) and board approval will fund the Bakken, Niobrara and East Texas development plans. In the Bakken, the company is currently running one rig from Paramount Drilling U.S. LLC. The company plans to add a second rig in the Bakken during the second quarter of 2012. In the Niobrara, the company is participating in a Devon operated well, and continues to evaluate the seismic work. Based on the results of the Devon operated well and the seismic data, the company expects to spud its first operated well in the second quarter of 2012 and begin full development in the third quarter of 2012.

In East Texas, the company will utilize the seismic work currently being performed to aid in the development in deep and shallow targets, including the Cotton Valley horizontal (Hz) targets which are comprised of 18% oil and natural gas liquids. Based on these targets' liquids contents and the increased availability and lower costs in the service sector, these targets are becoming more economic. Currently all four rigs from Helmerich& Payne are subleased to other operators. The Company expects to fund the 2012 capital expenditure plan from available cash and operating cashflow.

"Our objectives for the second half of 2011 have been to increase our cash reserves to fund our reposition of the company operations into oil/liquids drilling programs," says Ken L. Kenworthy, CEO. "The exchange offer will create $100 - $120 million in new liquidity, which ensures our ability to fund our CAPEX in 2012 and into 2013. I am pleased with the support we have received from our major bond holders in the form of the terms of the bond exchange we have announced. When completed, the exchange offer will create between $100 million and $120 million of new drilling capital.

"Our first oil well in the Bakken/Three Forks System Resource (B/3F), the Wock 21-1-1H has been successfully completed with an internally estimated EUR of 400,000 BOE, at current oil prices, this well will provide a 20+% return. The B/3F is a statistical play where expected EURs range from 300,000 - 800,000 BOE. Current drilling plans in North Dakota over the next several months will include wells in our two largest acreage positions in Billings and McKenzie counties, which contain 128 potential operated locations. This inventory for these two counties alone is 16 years for 1 rig. Over next several months, we should have a better view of the statistical spread of all our well results, non-op wells and those of others around all of our acreage. This production information will allow us to target the highest producing areas in our future development plans, resulting in our target average EUR of 500,000-600,000 BOE.

"Our Bakken, Niobrara and Cotton Valley Long Horizontal (CV Hz) development will all compete for our 2012 CAPEX budget. CV Hz development of 7,500' laterals, we estimate will cost about $7.5 MM and recover about 7.5 BCFE, including 18% oil and NGLs. Processing uplift plus declining completed well costs of 10%-15% make re-establishing a CV Hz drilling program very economical, with rates of return comparable in all three plays. Our expectations are that adding gas to our pipeline system, further cost softening in East Texas will increase our Endeavor Gas Gathering LLC value and rate of return on this program. This overall repositioning of our development plans funded by financial transactions should create ample liquidity to execute our plan, demonstrating the value and benefits of our multi-basin Four Resource play inventory."

Company Highlights for the Three and Nine Months Ended September 30, 2011

Transformation to Oil

Bakken

  • The company has successfully drilled and completed its first Bakken Petroleum System well. The Wock 21-1-1H, located in Stark County, was completed within the Three Forks and had a 24 hour IP test rate of 450 BOE. The Wock 21-1-1H is projected to have a peak 30 day average production of 275-300 BOE pending lateral cleanup and placing the well on pump. The expected EUR is 400 MBOE.
  • The company has successfully drilled its second Three Forks Hz well. The Frank 31-4-1H was drilled in Sections 4 & 9 Township 148N Range 98W in Stark County, North Dakota and reached a total depth of 21,058' with a Hz lateral length of 10,183'. The Frank 31-4-1H had a spud to TD of 38 days which represents a nine day improvement in the drilling of the Wock 21-1-1H. The Frank 31-4-1H is scheduled for a 40 stage completion in the month of November 2011.
  • The company has spud its third operated well in the Bakken Petroleum System in Billings County, North Dakota. The Evoniuk 21-2-1H is located in Sections 2 & 11 Township 142N Range 100W and was spud on October 25, 2011. The Evoniuk 21-2-1H will target the Three Forks and the well is expected to reach a total depth of 19,850' and a targeted lateral length of 9,500'.
  • We have received permits for three additional locations in McKenzie County, North Dakota and ten additional permits are in process. We expect to spud the Akovenko 24-34-1H well located in Sections 3 &1 0 Township 146N Range 99W in McKenzie County in the fourth quarter.
  • We expect to operate 52 (1,280-acre) units in North Dakota, with working interests averaging more than 45%. We anticipate working interests to average 50% to 75%. The 52 units have a potential for 208 locations, which is a twenty rig-year inventory development program.
  • The company has elected to participate in four non-operated wells targeting the Middle Bakken and Three Forks zones. Two of those wells have reached TD and two are currently drilling. Our working interests range from 2% to 25% and average 14%. We expect to participate in six additional non-operated wells that have been permitted with an average working interest of approximately 4%.

Niobrara

  • The company is a non-operating participant in the Devon Energy Newton Ranches 14-3444H well located in Section 34-T24N-R64W. This well is within the N. Mustang seismic project area and will test the Niobrara Formation. GMXR has a 29.2% working interest. The well reached a total depth of 12,045' with a Hz lateral length of 4,000' and is expected to be fracture stimulated in November of 2011. Our N. Mustang Doty-Hill, Goshen County seismic shoot encompassing 135 square miles has been completed and under evaluation.
  • The company is currently conducting a 204 square mile 3D seismic shoot that covers the majority of our Platte, Laramie and Southern Goshen County, Wyoming leases and expects to complete this shoot in the first quarter of 2012.
  • In Platte and Laramie Counties, Wyoming, GMXR owns 376 undrilled locations in 94 (640-acre) Niobrara units of which we expect to operate 70 units with 280 potential wells with an average of 64% working interest. GMXR has an average working interest of 78% in 49 of these units.
  • In Goshen County, Wyoming, GMXR has 208 undrilled 4,000' lateral locations in 52 (640-acre) Niobrara units of which we expect to operate 25 of these units containing 100 potential locations with an average working interest of 45%.
  • The company plans to study the seismic work and the Newton Ranches 14-3444H, and use the results to begin drilling operations in the Niobrara Formation in the late first quarter or early second quarter of 2012, with one vertical test well before taking the first well Hz in the third quarter of 2012 and beginning continuous drilling shortly thereafter.

Operational

  • Production for third quarter of 2011 was 6.1 Bcfe, an increase of 32% over the 4.7 Bcfe of production in the third quarter of 2010. The company completed one Haynesville/Bossier ("H/B") Hz well during the third quarter of 2011.
  • Production increased by 54% to 18.7 Bcfe in the first nine months of 2011 compared to 12.2 Bcfe in the first nine months of 2010.
  • In the current natural gas commodity price environment, the company has elected to temporarily suspend its H/B Hz drilling until natural gas prices and/or completed well costs support more economical development. The company completed its eighth and final 2011 H/B Hz well in the third quarter of 2011. Completed well costs in the H/B for third quarter of 2011 were approximately $8.6 million, which is unchanged from the second quarter of 2011.
  • The company's full year production guidance is expected to be in a range of 23.2 Bcfe to 24.0 Bcfe, with the midpoint of 23.6 Bcfe representing an increase of 35% from the 17.5 Bcfe in production for 2010.
  • The company is currently conducting a 3D seismic shoot (Crossroads) of 33 square miles, covering almost all of the company's contiguous operated acreage in Harrison County, Texas, to aid in a more complete assessment of several oil targets and proven natural gas developments. The Crossroads shoot is expected to be completed in the fourth quarter of 2011.

Financial

  • Net loss applicable to common shareholders was $68.9 million, or $1.21 per share, and $138.8 million, or $2.69 per share, for the three and nine months ended September 30, 2011, respectively.
  • Non-GAAP adjusted net loss applicable to common shareholders per share (1) was $0.07 and $0.16 for the three and nine months ended September 30, 2011, respectively.
  • Lease operating expenses were $0.52 and $0.48 per Mcfe for the three and nine months ended September 30, 2011, respectively, compared to $0.60 and $0.67 per Mcfe for the three and nine months ended September 30, 2010, respectively, or a decrease of 13% and 28% per Mcfe, respectively.
  • General and administrative expenses were $1.24 and $1.19 per Mcfe for the three and nine months ended, September 30, 2011, respectively, compared to $1.43 and $1.65 per Mcfe for the three and nine months ended September 30, 2010, respectively or a decrease of 13% and 28%, respectively.
  • Adjusted EBITDA (1) was $19.8 million and $60.2 million for the three and nine months ended September 30, 2011, respectively, compared to $16.6 million and $45.0 million for the three and nine months ended September 30, 2010, respectively.
  • Discretionary cash flow(1) of $11.7 million and $37.2 million for the three and nine months ended September 30, 2011, respectively, compared to $12.4 million and $34.4 million for the three and nine months ended September 30, 2010, respectively.
  • Revised cash capital expenditure budget for 2011 is approximately $283 million; of which $101 million is the cash portion of acreage acquisitions and $182 million is for drilling operations of which we estimate approximately 20% will be spent on oil related activities. As of September 30, 2011, we have made $242 million on of these planned capital expenditures.
  • Revised guidance for 2011 adjusted EBITDA (1) is expected to be $78 million.

Operational Update

Bakken

The company has successfully drilled and completed its first Bakken Petroleum System well. The Wock 21-1-1H located in Stark County was completed within the Three Forks and had a 24 hour IP test rate of 450 BOE. We are preparing to clean out the lateral and place the well on pump. We expect a peak 30 day average production of 275-300 BOE and an EUR of 400 MBOE. At current commodity prices and expected rates of production, the Wock 21-1-1H should provide a greater than 20% rate of return. In evaluating the results of the Wock 21-1-1H, the company would point to the fact that there is a high degree of variability in reported 30 day average IP rates as operators have reported rates less than and greater than 300 BOE/d across the entire basin including areas that are well established. While the projected 30 day average production of 275-300 BOE is below the company's 500 MBOE type curve, by year three the Wock 21-1-1H cumulative BOE is expected to be 75% of the 500 MBOE type curve which is consistent with the flatter decline curves on mature Three Forks producers. The company plans to continue to evaluate and adjust its completion designs in future drilling locations including the Frank 31-4-1H which is scheduled for completion in November 2011.

The company has successfully drilled its second Three Forks Hz well. The Frank 31-4-1H was drilled in Sections 4 & 9 Township 148N Range 98W in Stark County, North Dakota and reached a total depth of 21,058' with a Hz lateral length of 10,183'. The Frank 31-4-1H is scheduled for a 40 stage completion in the month of November 2011.

The company has spud its third operated well in the Bakken Petroleum System in Billings County North Dakota. The Evoniuk 21-2-1H is located in Sections 2 & 11 Township 142N Range 100W and was spud on October 25, 2011. The Evoniuk 21-2-1H will target the Three Forks and the well is expected to reach a total depth of 19,850' and a targeted lateral length of 9,500'. We have received permits for three additional locations in McKenzie County North Dakota and 10 additional permits are in process. We expect to spud the Akovenko 24-34-1H well located in Sections 3 & 10 Township 146N Range 99W in McKenzie County in the fourth quarter.

The company has approximately 600 undrilled 9,500' lateral locations in 150 units and expects to operate 52 units on its North Dakota and Montana leasehold of 35,524 net acres. These units have a potential for 208 locations, which is a twenty rig-year inventory. In the three counties of Billings, McKenzie and Stark the company has 42 units where we would expect to operate. On 1280-acre spacing units, our holdings in Billings County consist of 19 possible units and 76 well locations, our holdings in McKenzie County consist of 13 possible units and 52 well locations, our holdings in Stark County consist of 10 possible units and 40 well locations and our holdings in Richland County, Montana consist of 10 possible units and 40 well locations. Due to acreage swaps and trades, we expect our working interest in our operated units to be 50% to 75%. The company drilling CAPEX will be focused on areas delivering the best results and as a consequence we would expect our 30 day cumulative BOE average to improve over time and conform to the GMXR long lateral type curve of 500 MBOE.

The company has elected to participate in four non-operated wells targeting both the Middle Bakken and Three Forks zones. The working interests in these non-operated wells range from 2% to 25% and average 14%. The company has an interest in six additional non-operated wells that have been permitted with an average working interest of 4% in which we would expect to participate.

Our 2012 CAPEX plan includes adding a second rig in the Bakken Petroleum System in second quarter of 2012. With the expectation that we will participate in one non-operated well per month an average working interest of 5.0% and assuming a spud to spud cycle of 45 days, we expect to drill 21 gross and 8 net wells in 2012.

DJ Basin-Niobrara

The company has an undeveloped DJ Basin-Niobrara position covering 40,191 acres and is focused in two separate areas. As previously announced the company has nearly 584 undrilled Hz locations in 146 (640-acre) units and has participated in a two 3D seismic shoots.The first focus area is North Mustang-Doty Hill (NMDH) in Goshen County and consists 9,374 net acres and the company would expect to operate in 25 units containing 100 undrilled locations with an average working interest of at least 45%. The Company has participated in a 3D seismic shoot in NMDH (135 square miles) initiated by Devon Energy Corporation that covers the majority of the company's leases in Goshen County, Wyoming.

The company elected to participate in the drilling of the Newton Ranches 14-3444H well with the operator, Devon Energy Corporation, Oklahoma City, Oklahoma, (NYSE: DVN), for its 29.2% working interest. The Newton Ranches 14-3444H well is located in Section 34 Township 24N Range 64W, in Goshen County, WY. With the benefit of 3D seismic data, the well was drilled to a measured depth of 12,045' with a Hz length of 4,000' to test the Niobrara Formation. The Newton Ranches 14-3444H is scheduled for completion in November of 2011.

The second area of focus for the company is Chugwater in Platte and Laramie Counties and consists of 30,818 net acres and the Company expects to operate 70 units containing 280 undrilled locations with an average working interest of 64%. The company's 3D seismic shoot in Platte and Laramie Counties (204 square miles) should be completed in the first quarter of 2012. In all, the company will acquire in excess of 300 square miles of 3D seismic data to aid in our exploitation of the leases.

The company plans to drill a vertical pilot and core approximately 360 feet of the Niobrara Formation in the first quarter of 2012. The vertical pilot location chosen with the benefit 3D seismic would be then completed as a Hz well in 2012 after evaluation of the core. The company expects to deploy its first rig in the Niobrara in September of 2012.

East Texas Basin

The company's East Texas assets are focused on 25,224 net H/B acres and 17,200 Cotton Valley/Travis Peak (CVS/TP) acres. In the H/B the company has 39 producers, 27 proved undeveloped locations and 226 net undrilled locations. In the CVS/TP the company has 359 producers and projects 83 net 7,500' Hz locations.

The company completed and brought one new H/B Hz wells to production during the third quarter of 2011 and for the third quarter of 2011, our average completed well costs were $8.6 million which is unchanged from the second quarter of 2011. In the third quarter 2011, the Holt Blocker Heirs Blocker Ware #1H well was brought online August 14, 2011 and this well is the last H/B well before suspending H/B Hz drilling for the remainder of 2011. We are currently at 77 days of production, and we are projecting that this 6,534' lateral well will make in excess of 445 mmcfe during its first 90 days. The last two wells of the second quarter, the Baldwin Mercer 1H and the Holt Bosh 5H had 90 day volumes of 561 mmcfe and 544 mmcfe, respectively. In a review of the Company's long lateral H/B Hz program, first year production supports an average of 1.4 Bcfe. The current plan is to resume our H/B drilling program in the summer of 2013.

Recent reduction in completion costs have made if viable for the company to plan to resume a Cotton Valley (CV) Hz development program using longer laterals (7,500'). The company has 83 (7,500') Hz locations covering its core Cotton Valley acreage and intends to drill up to four CV Hz wells in 2012. The company expects completed well costs to be approximately $7.5 million and an EUR of 7.5 Bcfe.

The company plans to complete a 3D seismic shoot (Crossroads) of 33 square miles covering almost all of the company's contiguous operated acreage in Harrison County, Texas in the fourth quarter of 2011. The benefits of the Crossroads shoot include: (1) identification of additional oil targets for shallow and deep reservoirs in the Glen Rose and Travis Peak and potentially below the H/B gas shale; and (2) a more complete understanding of the joint and fracture systems of horizontal development of the Cotton Valley Sands and H/B assets.

Third Quarter 2011 Production and Realized Prices and Guidance for 2011 Production and Adjusted EBITDA

Production for the third quarter was 6.1 Bcfe, an increase of 32% from the third quarter of 2010, and a 6% decrease as compared to the second quarter 2011 of 6.5 Bcfe. The decrease in production can be attributed to temporarily suspending our H/B drilling program beginning in July 2011 and the normal decline in production form existing wells. The company expects full year 2011 production to be in a range between 23.2 Bcfe to 24.0 Bcfe, with the midpoint of 23.6 Bcfe representing an increase of 35% over the 17.5 Bcfe of production for 2010.

The company's realized natural gas price, excluding the effects of hedging, was 89% of the average NYMEX contract price for the third quarter of 2011. In the second quarter of 2011, the company's realized natural gas price was 90% of the average NYMEX contract for the quarter. The Company's realized gas price is based on a number of factors including (1) the price of gas at the physical sales points, (2) the amount of gas sold on a firm basis at a first of month index price and the amount of gas sold on a daily basis at the market price during the month of delivery, (3) the strike prices of the bought puts, sold puts, and other financial hedges compared to the NYMEX settlement price, (4) the recognition of option premium income received, less the recognition of option premium expenses paid, and (5) the fees paid to third parties to ship our gas to downstream market points.

Full-year adjusted EBITDA guidance for 2011 is now expected to be $78 million.

Financial Results for the Three and Nine Months Ended September 30, 2011

The company reported a net loss applicable to common shareholders of $68.9 million ($1.21 per basic and fully diluted share) and $138.8 million ($2.69 per basic and fully diluted share) for the three and nine months ended September 30, 2011, respectively, compared to net income applicable to common shareholders of $2.2 million ($0.08 per basic and fully diluted share) and of $3.0 million ($0.11 per basic and fully diluted share) for the three and nine months ended 2010, respectively.